Primary recovery generally results in an average recovery of only 25% of the oil originally in an oil bearing formation. Secondary recovery, water flooding, generally recovers another 10% by the time it becomes uneconomical to continue. It is not unusual, then, for 60% to 70% of the oil originally in the formation to remain when it becomes uneconomical to keep the field open.
Two major factors contribute to trapping this unrecovered oil in the formation. One of these is the capillary forces which arise because of the high oil/water interfacial tension. This problem is addressed by techniques such as CO.sub.2, N.sub.2, alkaline or surfactant flooding. The other major factor is the heterogeneity of the reservoir. There are always areas of the reservoir that are more permeable to the reservoir fluids than the rest of the reservoir. As the flow of fluids always occur through the areas of least resistance to flow, injected fluids tend to flow through the high permeability areas, bypassing the oil in the lower permeability areas. This problem is not directly addressed in CO.sub.2, N.sub.2 or chemical flooding. There are three basic procedures by which this phonomenon can be combated. One is to reduce the viscosity (resistance to flow) of all the fluids in the reservoir, for example by in situ combustion or steam flooding. Another is to increase the viscosity of the drive fluids, for example by polymer flooding. A third method is to partially or completely block off the high permeability areas of the reservoir. In situ combustion is difficult to control and maintain, and usually requires continuous O.sub.2 or air injection. It is only economical with heavy crudes. Using a high viscosity drive fluid has the major disadvantages of reducing flow rates, which is deleterious to the economics of a project, and of loosing large volumes of solution through the high permeability areas which have already been depleted of oil. Additionally, polymers tend to degrade in the reservoir because of the temperature, because of microbial actions and because of the shearing of the long polymer chains as the polymer solution is forced through the rock pores.
Two methods of partially or completely blocking the high permeability regions of the reservoir are currently being studied. One of these is the use of foams. Foams, however, are proving difficult to form in situ, and are not equilibrium structures; hence, they may degrade too quickly. Another promising procedures is to inject pulses of polymer solutions in a formation, interspersed with high concentrations of multivalent ions. In situ mixing then results in formation of a highly viscous gel. In addition to the drawbacks of polymer floods this technology has the additional drawback of requiring control of gelation time to delay gelation until the polymer solution is away from the well bore and into the high permeability regions of the reservoir before gelation occurs.